PO Box 910 Halifax, Nova Scotia Canada B3J 2W5

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1 PO Box 0 Halifax, Nova Scotia Canada BJ W June 0, 0 Doreen Friis Regulatory Affairs Officer/Clerk Nova Scotia Utility and Review Board 0 Lower Water Street, rd Floor P.O. Box, Unit M Halifax, NS BJ S Re: Nova Scotia Power Inc (NSPI) 0 Year System Outlook Report Dear Ms. Friis: Section... of the Wholesale Market Rules Regulations provides: Subject to any contrary order of the Board, the NSPSO shall submit the draft NSPSO system plan to the Board for the Board's public comment process and for any Board review, and shall publish the draft plan each year by the end of June. On behalf of the NSPSO, the 0 0 Year System Outlook is attached for the Board's review. Concurrent with this filing, NS Power will post this report on the NSPSO OASIS site at and assessments.aspx. Please provide any direction or questions on this filing to the undersigned. Yours truly, Mark Peachey LL.B. Manager, Capital Filings

2 Nova Scotia Utility and Review Board IN THE MATTER OF The Public Utilities Act, R.S.N.S., c.0, as amended Nova Scotia Power 0 Year System Outlook 0 Report June 0, 0

3 0 0 0 TABLE OF CONTENTS.0 INTRODUCTION....0 LOAD FORECAST....0 DEMAND SIDE MANAGEMENT FORECAST GENERATION RESOURCES.... Existing Generation Resources.... Changes in Capacity..... Burnside Combustion Turbine Unit # Return to Service..... Port Hawkesbury Biomass Conversion to Network Resource Interconnection Service.... Unit Utilization & Investment Plan..... Projections of Unit Utilization & Possible Retirement Paths..... Projections of Unit Sustaining Investment....0 NEW SUPPLY SIDE FACILITIES.... Potential New Facilities.... Maritime Link.... Other Opportunities..... OATT Transmission Service Queue..... Ongoing Tidal Energy Developments..... Opportunities for Regional Coordination Renewable to Retail....0 ENVIRONMENTAL AND EMISSIONS REGULATORY REQUIREMENTS.... Renewable Electricity Plan.... Environmental Regulatory Requirements....0 RESOURCE ADEQUACY.... Operating Reserve Criteria.... Planning Reserve Criteria..... Updated Planning Reserve Margin Loss of Load Expectation Study..... Analysis of Currently Planned Levels of Variable Generation Energy Resource Interconnection Service Connected Resources... DATE FILED: June 0, 0 Page of 0

4 0.. Energy Resource Interconnection Service to Network Resource Interconnection Service Conversion of Port Hawkesbury Biomass.... Load and Resources Review....0 TRANSMISSION PLANNING.... System Description.... Transmission Design Criteria.... Transmission Life Extension.... Transmission Project Approval.... Nova Scotia - New Brunswick Intertie Overview....0 TRANSMISSION DEVELOPMENT 0 TO Transmission Development Plans CONCLUSION... 0 DATE FILED: June 0, 0 Page of 0

5 0 0 0 LIST OF FIGURES Figure : Total Energy Requirement with Future DSM Program Effects... Figure : Coincident Peak Demand with Future DSM Program Effects... Figure : Annual DSM Savings during the Forecast Period... Figure : 0 Generating Resources... Figure : Firm Capacity Changes & DSM... Figure : Thermal Generation 0 Year Unit Utilization... Figure : Annual Investment by Asset Class... Figure : Annual Investment by Unit... 0 Figure : Generation Interconnection Queue... Figure 0: Renewable Generation Projects Currently in the Combined T/D Advanced Stage Interconnection Request Queue... Figure : OATT Transmission Service Queue... Figure : RES 0 and 00 Compliance Forecast... Figure : Compliance CO Emission Caps... Figure : Emissions Multi-Year Caps (SO, NO x )... Figure : Emissions Annual Maximums (SO, NO X )... Figure : Individual Units Limits (SO )... Figure : Mercury Emissions Caps... Figure : ELCC of Wind Generation... Figure : NS Power 0 Year Load and Resources Outlook... Figure 0: NS Power Major Facilities in Service 0... Figure : Conditions Determining Limits... APPENDICES Appendix A: IRP Action Plan and System Outlook Appendix B: System Design Criteria DATE FILED: June 0, 0 Page of 0

6 0 0.0 INTRODUCTION In accordance with the... Market Rule requirements, the Nova Scotia Utility and Review Board s (Board, UARB) direction provided in its letter dated December, 0, and the action items noted in the 0 Integrated Resource Plan (IRP) Final Report, this report provides NS Power s Ten Year System Outlook on behalf of the NS Power System Operator (NSPSO) for 0. In its letter of December, 0, the UARB provided its comments on NS Power s 0 0 Year System Outlook report, which referenced items including the Port Hawkesbury Biomass Plant (PHBP) upgrade to Network Resource Interconnection Service (NRIS), Burnside # s return to service, and the IRP. Accordingly, the 0 0 Year System Outlook report contains the following information: A summary of the NS Power load forecast in Section. Comments on the NS Power 0 Integrated Resource Plan Action Plans, in Sections.,.,. and.. Please also refer to Appendix A for the specific 0 IRP Action items reflected in this Report. An update on the Demand Side Management (DSM) forecast in Section. The NSPSO system plan will address: a) transmission investment planning; b) DSM programs operated by E or others; c) NS Power generation planning for existing Facilities, including retirements as well as investments in upgrades, refurbishment or life extension; d) new Generating Facilities committed in accordance with previous approved NSPSO system plans; e) new Generating Facilities planned by Market Participants or Connection Applicants other than NS Power; and f) requirements for additional DSM programs and / or generating capability (for energy or ancillary services). M0, NS Power Final Report, 0 Integrated Resource Plan, October, 0 pages -. DATE FILED: June 0, 0 Page of 0

7 0 0 A summary of generation expansion anticipated for facilities owned by NS Power and others in Section. A discussion of transmission planning issues in Section. Update on changes associated with the Port Hawkesbury Biomass Plant to proceed with Network Resource Interconnection Service (NRIS) service in Section... Update on analyses for Burnside Unit # generation in Section... Identification of transmission related capital projects currently in the Transmission Development Plan in Sections and. Forecast for generation unit retirements in Section... NS Power has concurrently posted this System Outlook on the NSPSO OASIS website. The 0 Outlook is based on the assumptions in the 0 IRP as well as NS Power s 0 Load Forecast. The IRP assumptions were developed by NS Power and the Board s consultants, with input from stakeholders. The 0 IRP Final Report included action items for follow-up in future 0 Year System Outlook reports. Many of the items from the 0 IRP Action Plan are referred to in this report. Please refer to Appendix A for a list of those action items and where they are addressed in this report. M0, NS Power 0 Load Forecast, April 0, 0, Exhibit N-. DATE FILED: June 0, 0 Page of 0

8 0 0.0 LOAD FORECAST The NS Power load forecast provides an outlook on the energy and peak demand requirements of in-province customers. The load forecast forms the basis for the investment planning and overall operating activities of NS Power. The figures presented in this report are the same as those in the 0 Load Forecast Report and were developed using NS Power s Statistically Adjusted End-Use (SAE) model to forecast the residential and commercial rate classes. The residential and commercial SAE models are combined with an econometric based industrial forecast and customer specific forecasts for NS Power s large customers to develop an energy forecast for the province, also referred to as a Net System Requirement (NSR). The values presented in the Figure and Figure below also reflect the effects of current and proposed Demand Side Management programs. The forecast for 0 assumes DSM values consistent with EfficiencyOne s (E) 0 DSM plan. The forecast for 0 onward is based on the new DSM franchise holder, EfficiencyOne (E), achieving DSM savings consistent with the Low DSM scenario from Efficiency Nova Scotia s (ENSC) Potential Study. This is also consistent with the Evidence submitted by NS Power to the Board on April 0, 0 in the proceeding to approve the 0 0 DSM Supply Agreement (M0). Figure shows historical and forecast net annual energy requirements. In general, the Net System Requirement is expected to remain flat for the duration of the forecast period. Anticipated growth in the different sector loads is expected to be offset by DSM M0, NS Power 0 Year Energy and Demand Forecast, Exhibit N-, April 0, 0 M0, Efficiency Nova Scotia Corporation Application for Approval of its Electricity Demand Side Management ( DSM ) Plan for 0, E-, September, 0 Navigant Consulting, Nova Scotia 0-00 Demand Side Management Potential Study, M0, Exhibit N-, January, 0. M0, Supply Agreement for Electricity Efficiency and Conservation Activities, NS Power Evidence, Exhibit E-, April 0, 0 DATE FILED: June 0, 0 Page of 0

9 initiatives. From 0 to 0, the NSR is forecast to increase at an annual rate of 0.0 percent, or grow at a rate of 0. percent if the impacts of DSM are excluded. Figure : Total Energy Requirement with Future DSM Program Effects 0 Year Total Energy Growth GWh % 00, , -. 00,. 00, , , 0. 0, , -.0 0,. 0,0 -. 0*,0-0. 0*, 0. 0*, 0. 0*,0 0. 0*, *, -0. 0*, -0. 0*,0-0. 0*, *,0-0. 0*,0-0. *Forecasted value NS Power also forecasts the peak hourly demand for future years. NS Power remains a winter peaking utility and, accordingly, the highest period of energy consumption in Nova Scotia is December through February due to the predominance of electric heating load over the relatively light summer air conditioning load within the province. The peak forecast is developed using end-use energy forecasts, combined with end-use peak fractions and peak-day weather conditions to generate monthly peak demand forecasts through an estimated monthly peak demand regression model. The peak DATE FILED: June 0, 0 Page of 0

10 contribution from large customer classes is calculated from historical coincident load factors for each of the rate classes. Monthly peak loss percentages are applied to each monthly sales peak to produce losses by class and are then summed to produce the total peak demand forecast. Figure shows the historical and forecast net system peak. Figure : Coincident Peak Demand with Future DSM Program Effects Interruptible Contribution to Peak (MW) Firm Contribution to Peak (MW) Net System Peak (MW) Growth (%) Year 00,, -. 00,, ,,. 00,0,. 00,, ,0,.0 0,0,. 0,0, -. 0,,0.0 0,0,. 0* 0,,0 -. 0*,,0 0. 0*,0, *,0,0 0. 0*,0, *,,0-0. 0*,,0-0. 0*,, *,, -0. 0*,, -0. 0*,,0-0. *Forecasted value DATE FILED: June 0, 0 Page of 0

11 0.0 DEMAND SIDE MANAGEMENT FORECAST DSM and conservation plans continue to play a role in the use of electricity in Nova Scotia. DSM is taken into account in the load forecast by adjusting the forecast for the year over year change in the cumulative impact of DSM savings. The cumulative impact represents the total energy savings on the electricity grid in a given year attributable to DSM programs. As noted above, the forecast for 0 assumes DSM values consistent with E s 0 DSM plan. The forecast for 0 onward is based on E achieving energy savings consistent with the Low DSM scenario from ENSC s Potential Study. The energy and demand savings of the Low DSM scenario are sufficient to avoid capacity additions for the 0 year planning period and further to 0. It is also noteworthy that utilization of the Low DSM level projects essentially flat net and peak system requirements meaning that any additional DSM would result in a reduction of those amounts. Figure summarizes annual projected demand and energy savings included in NS Power s Load Forecast in Section.0. DATE FILED: June 0, 0 Page 0 of 0

12 Figure : Annual DSM Savings during the Forecast Period Year Incremental GWh Savings Incremental MW Savings DATE FILED: June 0, 0 Page of 0

13 0.0 GENERATION RESOURCES. Existing Generation Resources Nova Scotia s generation portfolio is comprised of a mix of fuel types that includes coal, petroleum coke, light and heavy oil, natural gas, biomass, wind, tidal and hydro. In addition, NS Power purchases energy from independent power producers located in the province and imports power across the NS Power/NB Power intertie. Figure lists NS Power s generating stations/systems along with their fuel types and net operating capacities. It has been updated to include changes and additions effective up to January, 0. DATE FILED: June 0, 0 Page of 0

14 Figure : 0 Generating Resources Plant/System Winter Net Fuel Type Capacity (MW) Avon Hydro. Black River Hydro. Lequille System Hydro. Bear River System Hydro. Roseway / Harmony Hydro 0.0 Tusket Hydro. Mersey System Hydro. St. Margaret s Bay Hydro 0. Sheet Harbour Hydro 0. Dickie Brook Hydro. Wreck Cove Hydro 0.0 Annapolis Tidal Hydro. Fall River Hydro 0. Total Hydro. Tufts Cove Heavy Fuel Oil/Natural Gas Trenton Coal/Pet Coke/Heavy Fuel Oil 0 Point Tupper Coal/Pet Coke/Heavy Fuel Oil Lingan Coal/Pet Coke/Heavy Fuel Oil Point Aconi Coal/Pet Coke & Limestone Sorbent (CFB) Total Steam Tufts Cove Units, & Natural Gas. Total Combined Cycle. Burnside 0 Light Fuel Oil 0 Tusket Light Fuel Oil Victoria Junction Light Fuel Oil 0 Total Combustion Turbine Pre-00 Renewables Independent Power Producers (IPPs). Post-00Renewables (firm) Independent Power Producers. NS Power wind (firm) Wind. Community-Feed-in-Tariff (firm) Independent Power Producers. Total IPPs & Renewables.0 Total Capacity.0 Roseway / Harmony hydro system is undergoing refurbishment. The timing of the return to service of the Roseway portion of the system is pending decisions with regards to level of refurbishment. The Harmony portion of the system is forecasted to return to service in 0. The capacity of the Annapolis Tidal unit is based on an average performance level at peak time. Nameplate capacity (achieved at low tide) is. MW. 0 Burnside Unit # (winter capacity of 0 MW) is presently unavailable but is planned to be returned to service in winter 0/0. A System Impact Study required to confirm transmission system ability to accommodate additional Tusket capacity is in progress. The assumed firm capacity value of wind depends on the type of interconnection service. If the project is designated as an Energy Resource Interconnection Service (ERIS) it may not possess one or more physical characteristics required in order to provide capacity service. Consistent with the Generation Interconnection Procedure (GIP), their firm capacity is assumed to be zero. If the project is designated as a Network Resource Interconnection Service (NRIS) then it is considered as firm for capacity planning because it possesses the necessary physical characteristics and transmission capacity to ensure its full operation in all hours of the year. DATE FILED: June 0, 0 Page of 0

15 0. Changes in Capacity Figure provides the firm Supply and Demand Side Management capacity changes in accordance with the assumption set developed for the 0 IRP and the 0 Load Forecast. Figure : Firm Capacity Changes & DSM New Resources 0/0 0/0 Net MW DSM firm 00 Hydro Community Feed-in Tariff (Firm) Renewable Electricity Administrator Projects (Firm) Biomass Maritime Link Import - Base Block Burnside # return to service 0 Assumed Unit Retirements/Lay-ups - Total Firm Supply & Demand MW Change Projected Over Planning Period.. Burnside Combustion Turbine Unit # Return to Service In its letter of December, 0, the Board provided the following: Hydro capacity reflects the assumption that the Harmony hydro facility will be refurbished. The Community Feed-in-Tariff represents distribution-connected renewable energy projects as outlined in the Province s Renewable Electricity Plan in April 00. The projects are assumed to be phased-in over years starting in 0. NRIS wind projects awarded by the Renewable Electricity Administrator (REA) assumed to be in-service for the 0 RES (South Canoe and Sable). Biomass shown includes a small Independent Power Producer (IPP) expected in-service within the 0 year period (0 MW) as well as MW from the PH Biomass plant, subject to operational validation. As per the unit retirement/lay-up assumptions of the 0 IRP. DATE FILED: June 0, 0 Page of 0

16 0 0 0 In response to the Board IR-, NSPI stated that it had not completed this alternative analysis but that its 0 Annual Capital Expenditure ("ACE") plan includes projects that would support returning Burnside # to service in 0. The Board looks forward to reviewing NSPI's supporting analysis. Burnside Unit # is a 0 MW combustion turbine located in the Burnside Industrial Park in Dartmouth that provides black start capability, 0 minute reserve, dynamic reactive reserve, reactive power support and additional firm capacity to the NS Power electrical system. Unit # was originally commissioned in and has been out of service since 00. NS Power is currently forecasting an expected return to service for Burnside Unit # in the winter of 0/0, subject to submission of the projects relating to the unit refurbishment plan in the 0 Annual Capital Expenditure (ACE) Plan and subsequent UARB approval of these projects. The supporting analysis for the unit refurbishment plan will be included in the ACE Plan submission to the Board... Port Hawkesbury Biomass Conversion to Network Resource Interconnection Service The Port Hawkesbury Biomass generating unit is presently an Energy Resource Interconnection Service (ERIS) classified resource which will be converted to NRIS following the system upgrades scheduled to take place in advance of the Maritime Link coming online. The System Impact Study GIP-IR-SIS-R0, conducted by the NSPSO, concluded that MW of PH Biomass net capacity can be counted as NRIS. Please also refer to Section.... Unit Utilization & Investment Plan Pursuant to the 0 IRP Final Report and Action Plan, NS Power committed to the following items: DATE FILED: June 0, 0 Page of 0

17 0 0 0 Continue the thermal generation asset analysis work from the IRP process. By the end of June 0, file an initial thermal asset management plan striving to optimize the level of sustaining capital expenditures required for the fleet of coal/oil/gas plant. Update this plan each year in the 0 Year System Outlook Report. The plan will include the following: Recognition of uncertainty of many elements involved in this form of analysis. Recognition of/adherence to planning reserve margin requirement and level of planning reserve surplus associated with different net firm peak load trajectories based on then-anticipated DSM peak reductions and associated net firm peak load forecast. Projections of possible retirement paths for the thermal fleet. Prioritization of units or plans for retention given system constraints. Consideration of locational value of Tufts Cove plant, and flexible operating characteristics of gas and oil-fired steam units compared to coalfired units. There may be locational or system considerations that could give preference to sustaining capital or life extension expenditures at the Tufts Cove location compared to other plants. Consideration of location of other system resources, either NS Powerowned or IPP-owned, and their capacity value. Consideration of unit utilization forecasts and the significant driver that operating hours is for maintenance investment. DATE FILED: June 0, 0 Page of 0

18 0 0 NS Power is in the process of developing a unit utilization and investment plan to analyze and optimize the level of sustaining capital expenditures required for the fleet with consideration of the items above. The initial draft of the plan includes the Company s projections of possible retirement paths for the thermal fleet and the prioritization of units for retention given system constraints and is included in Sections.. and... NS Power is working to address the additional considerations and will provide an updated Unit Utilization & Investment Plan in the 0 0 Year System Outlook report... Projections of Unit Utilization & Possible Retirement Paths As concluded in the results of the 0 IRP, there are two generating units that are candidates for retirement within the 0 year planning window. Lingan is a possible retirement, starting in 0, when the Maritime Link comes online providing capacity service equivalent to that of Lingan. Tufts Cove Unit # was also identified as a potential retirement candidate in 0. Where economically feasible, NS Power would work to preserve low utilization factor steam generating units to be recalled to service should the capacity or energy be required. The introduction of renewable generation to meet the 0 and 00 Renewable Electricity Regulations requirements has significantly influenced the operating and dispatch patterns of NS Power s fleet of steam units. Units designed for base-loaded operation are required to provide much more flexible operations in order to achieve the required load and wind following behaviour. Asset management practices manage and project costs for all units based on their anticipated utilization, as shown in Figure. For units that have limited future service planned, investments are managed accordingly. DATE FILED: June 0, 0 Page of 0

19 Figure : Thermal Generation 0 Year Unit Utilization Planned Capacity Factor Anticipated Flex Utilization Planning Retire Major U Low High Unit High Med Low U Low shift Load Cycle 0 Lay Up Foreca Maint st Int LIN Planned Planned Planned U Low Post 00 Under Review LIN Planned Planned 0 retire LIN Planned Planned Under Assess. Planned 0 LIN Planned Planned Under Planned Assess. 0 POA Planned 0 POT Planned Future Planned 0 TRN Planned Planned 00 TRN Planned Future Planned 0 TUC Planned Planned 0 U Low Under Planned Planned Planned Post Under Assess. TUC 0 Review TUC ` Planned Planned Under Assess. Planned U Low Post 0 Under Review TUC,, Planned Planned Planned 00 CTs Planned Planned 0 yr plan PHB Planned 0 Note: For Asset Management purposes units are anticipated to be able to provide these generation services; retirements and next major maintenance interval are forecasted. Unit will be operated with two-shifting. Unit rarely operated but retained as a capacity resource with annual capacity factor less than %. 0 Unit operated with two-shifting at annual capacity factor less than 0% but greater than 0%. Unit will be operated with a seasonal lay-up program in place. Under Assessment DATE FILED: June 0, 0 Page of 0

20 .. Projections of Unit Sustaining Investment The sustaining investment that matches the unit utilization plan in Section.. is outlined in Figures and below. Major assets are regularly re-assessed as to their condition and intended service. The utilization plan, investment plan and maintenance strategy are adjusted based on the latest asset health information and strategic input. Figure : Annual Investment by Asset Class 0 DATE FILED: June 0, 0 Page of 0

21 Figure : Annual Investment by Unit TUC0, TRN0, and LIN0 are references to common plant investments not specific to a unit. DATE FILED: June 0, 0 Page 0 of 0

22 0.0 NEW SUPPLY SIDE FACILITIES. Potential New Facilities As of June, 0, NS Power has 0 Active Transmission Connected Interconnection Requests ( MW) and Active Distribution Connected Interconnection Requests ( MW) at various stages of interconnection study. Of these, there are transmission connected projects and distribution connected projects that are currently in the Combined T/D (Transmission/Distribution) Advanced Stage Interconnection Request Queue. Proponents of the transmission projects have requested NRIS or ERIS. Distribution projects do not receive an NRIS or ERIS designation. NRIS refers to a firm transmission capacity request with the potential requirement for transmission reinforcement upon completion of the System Impact Study (SIS). ERIS refers to a requested capacity but only to the point where transmission reinforcement will not be required. Results of the interconnection studies will be incorporated into future transmission plans. Figure provides NS Power s Advanced Stage Interconnection Request queue as of June, 0. DATE FILED: June 0, 0 Page of 0

23 Figure : Generation Interconnection Queue Combined T/D Advanced Stage Interconnection Request Queue Publish Date: Wednesday, June, 0 Queue Order IR # Request Date DD-MMM- YY County Gross MW Summer Gross MW Winter Interconnection Point Type In-service date DD-MMM- YY Status Service Type -D -Dec-0 Cumberland N- Tidal -May- GIA Executed N/A -T -Aug-0 Hants L-0 Steam 0-Sep- GIA Executed NRIS -D 0-Sep- Pictou.. N- Wind -Jun- GIA Executed N/A -D 0-Sep- Pictou.. N- Wind -Jun- GIA Executed N/A -D 0-Aug- Halifax 0 0 H- Wind -Oct- GIA Executed N/A -D -Dec-0 Halifax.0.0 0H- Wind 0-Oct- GIA Executed N/A -T -Nov- Lunenburg L-00 Wind -Oct- GIA Executed NRIS -T -Nov- Lunenburg L-00 Wind -Oct- GIA Executed NRIS -T -Jul- Richmond.. C Biomass 0-Jan- SIS Complete NRIS 0-D -May- Pictou N-0 Wind 0-Oct- GIA Executed N/A -D 0 0-Aug- Pictou N-0 Wind 0-Oct- GIA Executed N/A Cape -D 0 -May- Breton S-0 Wind 0-Apr- GIA Executed N/A -D 0-Sep- Colchester.. N-0 Wind -Jun- GIA Executed N/A Distribution projects are not designated ERIS or NRIS so the Service type is shown as N/A. DATE FILED: June 0, 0 Page of 0

24 Queue Order IR # Request Date DD-MMM- YY -D 0-Jun- -D 0 -Jun- -D -Oct- In-service date DD-MMM- YY County MW Summer MW Winter Interconnection Point Type Status Cape Breton.. S-0 Wind 0-Aug- GIA Executed N/A Cape Breton S-0 Wind 0-Mar- GIA Executed N/A Cape Breton S-0 Wind 0-Mar- GIA Executed N/A Service Type -D 0-Sep- Colchester.. N-0 Wind -Jun- GIA Executed N/A -D -Sep- Cape Breton.. S-0 Wind 0-Dec- GIA Executed N/A -D -May- Cape Breton S-0 Wind 0-Dec- GIA Executed N/A 0-D -Sep- Hants V- Wind -Feb- GIA Executed N/A -D -Feb- Yarmouth.. W-0 Wind -Feb- GIA Executed N/A -D -Feb- Hants V-0 Wind 0-Feb- GIA Executed N/A -D -Jun- Halifax.. H- Biomass 0-May- GIA Executed N/A -T -Aug- Lunenburg.. V Wind -Aug- GIA Executed NRIS -D 0-Dec- Halifax.. H- Wind 0-Dec- GIA Executed N/A -D -Dec- Hants V- Biogas -Dec- GIA Executed N/A Cape -D -Feb- Breton S-0 Biogas 0-Jun- GIA Executed N/A -D -Jul- Victoria.. 0S- Wind -Feb- GIA Executed N/A Cape -D -Dec- Breton S-0 Wind 0-Aug- GIA Executed N/A DATE FILED: June 0, 0 Page of 0

25 Queue Order IR # Request Date DD-MMM- YY County MW Summer MW Winter Interconnection Point Type In-service date DD-MMM- YY Status Service Type 0-D 0-Aug- Hants V-0 Wind 0-Feb- GIA Executed N/A -D -Aug- Colchester N-0 Wind -Jun- GIA Executed N/A -D -Nov- Halifax.. 0H-0 Wind -Dec- GIA Executed N/A -D -Apr- Cumberland N-0 Wind 0-Oct- GIA Executed N/A -T 0 0-Aug- Yarmouth L-0 Gas 0-Nov- SIS in Progress NRIS -T 0 0-Aug- Digby.. V-0 Tidal 0-Jun- FAC in Progress ERIS -D 0 0-Jun- Lunenburg.. 0W- Biomass -Aug- GIA in Progress N/A -D 0-Feb- Colchester.. N- Biomass 0-Jun- GIA in Progress N/A -D -Apr- Antigonish C- Biogas -Jan- GIA Tendered N/A -D 0 0-Jun- Guysborough.. C- Wind 0-Mar- GIA Tendered N/A 0-D 0 -Aug- Cape Breton S-0 Wind 0-Dec- GIA Executed N/A -T 0-Dec- Cumberland N Tidal 0-Jul- SIS in Progress NRIS -T -Dec- Cumberland N Tidal 0-Sep- SIS in Progress NRIS -D -Dec- Hants V-0 Biogas 0-Aug- SIS in Progress N/A -D 0-Jan- Colchester.. H-0 Wind -Nov- SIS in Progress N/A Totals.. DATE FILED: June 0, 0 Page of 0

26 0 All active transmission and distribution requests not appearing in the Combined T/D Advanced Stage Interconnection Request Queue are considered to be at the initial queue stage as they have not yet proceeded to the SIS stage of the Generator Interconnection Procedures (GIP). Figure 0 indicates the location and size of the generating facilities currently in the Combined T/D Advanced Stage Interconnection Request Queue. Figure 0: Renewable Generation Projects Currently in the Combined T/D Advanced Stage Interconnection Request Queue Company/Location Nameplate Capacity (MW) IR # Biomass in Hants County 0. IR # Wind in Hants County IR # Wind in Hants County IR # (NRIS version of existing MW IR, which was ERIS) N/A IR i # Wind in Lunenburg County. IR #0 Tusket Combustion Turbine (Upgrade from MW to 0MW) IR #0 Tidal in Digby County. IR # Tidal in Cumberland County IR # Tidal in Cumberland County Legacy Distribution Interconnection Request COMFIT Distribution Interconnection Requests. Total New Facilities Nameplate Capacity. Included in the Advanced Stage Request Interconnection Queue are: a 0. MW transmission biomass project with Generator Interconnection Agreement (GIA) executed; 0 MW of transmission wind projects with GIA executed, currently in Trial Operation; MW of net capacity converted to NRIS from existing ERIS please refer to Section.. DATE FILED: June 0, 0 Page of 0

27 0 0 0 a. MW transmission biomass project that completed the GIP process and was built based on an ERIS interconnection that has been resubmitted as a second Interconnection Request (IR) to study NRIS interconnection service. Port Hawkesbury Biomass,. MW gross / MW net output, generating unit is presently an ERIS classified resource which will be converted to NRIS following the system upgrades which are scheduled to take place in advance of the Maritime Link coming online; a. MW transmission wind project with GIA executed; an increase of MW to an existing transmission combustion turbine, at the SIS stage; a. MW distribution tidal project at the Facilities Study stage; a total of MW of transmission tidal projects at the SIS stage; a MW legacy distribution tidal project with Standard Small Generator Interconnection Agreement (SSGIA) complete; and. MW of distribution Community Feed-In Tariff (COMFIT) wind, biogas, and biomass projects at or beyond the SIS stage.. Maritime Link Pursuant to the 0 IRP Final Report and Action Plan, NS Power committed to the following items: Complete the integration of the Maritime Link. DATE FILED: June 0, 0 Page of 0

28 0 0 0 Execute the Maritime Link transmission investments. On November, 0, the Nova Scotia Utility and Review Board approved the Maritime Link Project. The Maritime Link Project is a 00 MW high voltage direct current (HVDC) transmission link between Nova Scotia and Newfoundland that will provide access to energy from Muskrat Falls Hydro Project in Labrador. The Maritime Link is scheduled to go in service in late 0. The energy available from the Maritime Link is contracted in components. First is the Nova Scotia Block which provides MW of firm capacity, on-peak hours per day. NS Power will also receive a Supplemental Energy Block of approximately 0 GWh annually for the first five years of operation, delivered in the overnight hours of November through March. Economic Energy above the base Nova Scotia Block and the Supplemental Energy Block will also be available at market prices. NS Power capital work orders related to the Maritime Link include the following: - L Rebuild/Upgrade Line Terminals - Separate L00/L00 on Canso Crossing Double Circuit Tower 0 - Upgrade L and L0 Thermal Rating 0 - N Onslow KV Node Swap CIs, 0 and 0 were submitted to the Board for review and approval in late 0 and early 0. CI is expected to be submitted to the UARB in Q 0. Please refer to those filings for further details on the associated Maritime Link transmission capital work. The Maritime Link energy is a critical component of NS Power s plan to meet the Nova Scotia 00 renewable energy targets. DATE FILED: June 0, 0 Page of 0

29 . Other Opportunities.. OATT Transmission Service Queue Figure : OATT Transmission Service Queue OATT Transmission Service Queued System Impact Studies Number Project Date & Time of Service Request TSR 00 July, 0 : PM TSR 0 November, 0 TSR 0 November, 0 TSR 0 December, 0 TSR 0 December, 0 Project Type Point to Point Point to Point Network Point to Point Revised June, 0 Project Location Requested In- Service Date Project size (MW) Status NS-NB Jan, 0 0 Facilities Study in progress of Parts Complete NB - Lunenburg Co. Lunenburg Co. NB - Kings Co. Jan, 0 Service Agreements in Progress Oct, 0 0. (.) Service Agreements in Progress Oct, 0 Service Agreements in Progress Network Kings Co. Oct, 0. (.) Service Agreements in Progress TSR 0 March, 0 Network Riverport Oct., 0. Applications In progress 0 TSR 0 April, 0 Network Antigonish Oct., 0. Applications In progress DATE FILED: June 0, 0 Page of 0

30 0 0.. Ongoing Tidal Energy Developments Pursuant to the 0 IRP Final Report and Action Plan, NS Power committed to the following item: Monitor ongoing developments of tidal energy and report to the UARB as part of the 0 Year System Outlook Report filed annually in June. The Nova Scotia Department of Energy issued a call for applications for a Tidal Energy Feed-In Tariff (Tidal FIT), and the Province awarded the following allocations of Tidal FIT in December 0 to the four Fundy Ocean Research Centre for Energy (FORCE) berth holders: Berth Holder Allocation (MW) Cape Sharp Black Rock Minas Energy Atlantis. The FORCE Parrsboro tidal facility is currently the only site in the province where transmission scale tidal energy projects are in development. FORCE is in the process of upgrading their existing MW substation to 0 MW in anticipation of the four berth holders connecting their demonstration projects to the network. The four berth holders' plans for development are summarized below:. Emera Inc. have partnered with OpenHydro to form Cape Sharp Tidal which will facilitate the development of tidal energy projects in the Bay of Fundy, Nova Scotia. The group will initially deploy two MW OpenHydro turbines at Berth D in 0. DATE FILED: June 0, 0 Page of 0

31 Black Rock Tidal Power intends to install their first platform carrying an array of smaller turbines in 0 (. MW in total). In subsequent years, they will extend the platform to its full capacity of. MW and then install a second platform taking the total to MW of generation.. The intended timeline for installation of the Minas Energy turbines is not yet known.. Atlantis Resources have partnered with Lockheed Martin and Irving Shipbuilding. Their plan is to install three. MW turbines at the FORCE site, but their timeline for doing so is not yet known... Opportunities for Regional Coordination Pursuant to the 0 IRP Final Report and Action Plan, NS Power committed to the following items: Monitor cost-effective market opportunities (imports and exports) as well as enhancements in regional balancing and interconnection and report on developments in the 0 Year System Outlook Report. During 0, continue discussions with Newfoundland (NALCOR) and New Brunswick (NB Power) on greater regional electric system coordination: Provide an annual update to the UARB. Discuss need, impacts, and cost allocation associated with a second kv line to New Brunswick. Explore mechanisms to advance efficient regional unit commitment, dispatch, and operating reserve sharing policies. DATE FILED: June 0, 0 Page 0 of 0

32 0 0 Regarding discussions with New Brunswick Power, on March, 0, NS Power and NB Power announced a month pilot project involving the cooperative dispatch of generation resources by the two utilities. There are two principles that underpin the co-operative dispatch agreement: It is more cost-effective to co-operatively optimize the generation resources of the two utilities to serve customers in the region, and Benefits resulting from the optimization should be shared equally between the utilities for the benefit of their customers. NS Power and NB Power have entered the pilot project in order to better understand, through real-system operations, how best to use their respective resources to maximize value. There are a number of key questions that can only be answered through analysis of the day-to-day operations of a co-operatively dispatched system, including the magnitude of customer savings and the extent to which the systems can be collectively optimized. At this stage in the pilot project, NS Power and NB Power are in the process of examining each other s generation resources, dispatch systems, reserve requirements and operating practices, as well as forecasting and operating parameters. With regards to the 0 IRP Action Plan commitment to report on regional coordination discussions with NALCOR, NS Power continues to monitor potential opportunities for further regional electric system coordination with Newfoundland and will report to the UARB as discussions develop regarding these opportunities. NS Power continues to monitor and evaluate a second kv line to New Brunswick. The timing and configuration of an expansion to the provincial intertie has yet to be DATE FILED: June 0, 0 Page of 0

33 0 0 determined; however, the Company is of the view that likely an upgrade may be required over the next decade. Please refer to Section. for further details... Renewable to Retail Pursuant to the 0 IRP Final Report and Action Plan, NS Power committed to the following item: File Renewable to Retail Tariff Application by September, 0. In accordance with provincial legislation, NS Power is conducting a stakeholder engagement process to develop market mechanisms and regulatory processes to support the sale of low impact renewable energy generated in-province by independent power producers to retail electricity customers. NS Power is required to file an application with the UARB for amendments to the Open Access Transmission Tariff, and other tariffs and procedures required to enable this market opening on or before September, 0. If new, qualified, low-impact renewable generation is built in Nova Scotia by independent power producers and sold directly to end customers in the Renewable to Retail market, NS Power will incorporate this information into transmission and generation planning. NS Power will continue to serve customers as the default supplier and will supply back-up and top-up services. DATE FILED: June 0, 0 Page of 0

34 0 0.0 ENVIRONMENTAL AND EMISSIONS REGULATORY REQUIREMENTS. Renewable Electricity Plan In April 00, the Nova Scotia Department of Energy (DOE) released its Renewable Electricity Plan, which set out the Province s commitment to renewable electrical energy supply. This plan includes a legislated renewable energy requirement of percent of net energy sales in 0, and 0 percent by 00. In addition to these targets, the Government s plan included a Community Based Feedin-Tariff (COMFIT) for community owned projects connected to the distribution system and provided for enhanced net-metering for renewable projects up to MW in capacity. COMFIT and distribution connected projects are eligible to meet RES requirements as the energy is realized in a particular year. However, for planning purposes this energy is not counted towards forecasts of RES compliance. The Enhanced Net Metering program was initiated in July of 0, and implementation of the COMFIT program occurred in September of 0. NS Power s production tracking and forecast for the current year indicate that percent renewable RES compliance will be achieved for the year 0. Figure below outlines the forecast RES compliance for 0 and 00. DATE FILED: June 0, 0 Page of 0

35 Figure : RES 0 and 00 Compliance Forecast All units in GWh PH Mill PH Mill On PH Mill On Off Compliance Year RES 0 RES 00 RES 00 Net System Requirement (GWh),,0 0, DSM effects NSR less DSM,, 0,0 Sales 0, 0,, RES % % 0% 0% RES Requirement (GWh) NSPI Wind Post 00 IPPs PH Biomass Project 0 0 COMFIT Distribution Connected IPPs Committed Eligible Pre 00 IPPs Eligible NSPI Legacy Hydro Maritime Link 0 REA procurement South Canoe/Sable 0 Forecasted Renewable Energy (GWh) Surplus or Deficit () 0 () COMFIT and distribution connected generation is not included for the purpose of RES compliance planning as provided in the Renewable Electricity Regulations made under Section of the Electricity Act: In planning for meeting its obligations under subsections () and () NSPI must not include electricity from distribution system connected renewable energy generators. 0 The Port Hawkesbury Paper Mill is approved to operate under a Load Retention Tariff until the end of 0. As such, the compliance forecast figures are shown both inclusive and exclusive of the PHP customer load. 0 Load Forecast Report. Cumulative DSM effects as per 0 Load Forecast Report, plus the anticipated impact of converting to LED streetlights. PH Biomass forecasted output. 0 DATE FILED: June 0, 0 Page of 0

36 0 0 The generation from COMFIT and distribution-connected IPPs can, however, be used for actual RES compliance: In meeting its obligations under subsections () and (), NSPI may include other sources of renewable electricity, including: (a) contributions from distribution system connected renewable energy generators.. Environmental Regulatory Requirements The Nova Scotia Greenhouse Gas Emissions Regulations specify emission caps for the period as outlined in Figure. The net result is a hard cap reduction from 0.0 to. million tonnes over that 0 year period, which represents a percent reduction in CO release over 0 years. The primary means of meeting the caps is a reduction in thermal generation from the existing generating units. Figure : Compliance CO Emission Caps Compliance Period Calendar Years Emission Cap for all Facilities (million tonnes CO eq ) 00, 0. 0, 0.0 0, 0, 0. 0, 0, , 0, 0, , 0, 0, The Nova Scotia Air Quality Regulations specify emission caps for sulphur dioxide (SO ), nitrogen oxide (NO X ), and mercury (Hg). The Regulations were extended from DATE FILED: June 0, 0 Page of 0

37 0 00 to 00 effective January, 0. The amended regulations replaced annual limits with multi-year caps for the emissions targets for SO and NO X as outlined in Figure. The regulations also provide local annual maximums, as well as limits on individual units for SO, as provided in Figure and Figure respectively. The mercury emission caps are outlined in Figure. By 00, emissions of sulphur dioxide from generating electricity will be reduced by percent from 00 levels. Nitrogen oxide will decrease by per cent from 000 levels and mercury will decrease per cent from 00 levels. SO reductions are being addressed mainly by reduced thermal generation and changes to fuel blends. NO X reductions are being addressed through reductions in thermal generation and the previous installation of Low NO X Combustion Firing Systems. Mercury reductions are being accomplished through reduced thermal generation, changed fuel blends and the use of Powder Activated Carbon systems. Figure : Emissions Multi-Year Caps (SO, NO x ) Multi-Year Caps Period SO (t) NO x (t) 0 0 (equal outcome) 0,00,0 00,0, 0 0,000,000 0,000, ,000, ,000,00 DATE FILED: June 0, 0 Page of 0

38 0 Figure : Emissions Annual Maximums (SO, NO X ) Year SO Annual NO X Annual Maximum (t) Maximum (t) 0 0,00, 0 0,0, 0-0,000,00 Figure : Individual Units Limits (SO ) Year SO Individual Units Limit 0 0, 00 0,0 0 0,0 00,00 Figure : Mercury Emissions Caps Year Hg Emission Cap (kg) The amendments to the Regulations also provide an optional program, until the end of 00, through which NS Power can make up deferred mercury emission requirements from earlier in the decade. NS Power can offer a mercury recovery program, such as recycling light bulbs or other mercury-containing consumer products, which would reduce the amount of mercury going into the environment. Annual maximums apply to the multi-year ranges from Figure only. Please refer to Figure for the caps on years that are not contained within the multi-year cap ranges. DATE FILED: June 0, 0 Page of 0

39 RESOURCE ADEQUACY. Operating Reserve Criteria As a member of the Maritimes Area of the Northeast Power Coordinating Council (NPCC), NS Power meets the operating reserve requirements as outlined in NPCC Regional Reliability Reference Directory #, Reserve. These Criteria are reviewed and adjusted periodically by NPCC. The Criteria require that: Each Balancing Authority shall have ten-minute reserve available that is at least equal to its first contingency loss and, Each Balancing Authority shall have thirty-minute reserve available that is at least equal to one half its second contingency loss. In the Interconnection Agreement between Nova Scotia Power Incorporated and New Brunswick System Operator (NBSO), NS Power and NB Power have agreed to share the reserve requirement for the Maritimes Area on the following basis: The Ten-Minute Reserve Responsibility, for contingencies within the Maritimes Area, will be shared between the two Parties based on a CP [coincident peak] Load-Ratio Share. Notwithstanding the Load-Ratio Share the maximum that either Party will be responsible for is 00 percent of its greatest, on-line, net single contingency, and, NSPI shall be responsible for 0 MW of Thirty-Minute Reserve. When Point Aconi is online, NS Power maintains a ten minute operating reserve of MW (equivalent to Point Aconi net output when on-line), of which approximately MW is held as spinning reserve on the system. Additional regulating reserve is maintained to manage the variability of customer load and generation. New Brunswick's new Electricity Act (the "Act") was proclaimed on October, 0. Among other things, the Act establishes the amalgamation of the New Brunswick System Operator (NBSO) with New Brunswick Power Corporation ("NB Power"). DATE FILED: June 0, 0 Page of 0

40 0 0 0 NS Power performs an assessment of operational resource adequacy covering an month period twice a year (in April and October preceding the summer and winter peak capacity periods). These reports of system capacity and adequacy are posted on the NS Power OASIS site in the Forecast and Assessments Section.. Planning Reserve Criteria.. Updated Planning Reserve Margin Loss of Load Expectation Study Pursuant to the 0 IRP Final Report and Action Plan, NS Power committed to the following item: Report on the ongoing evaluation of the planning reserve margin for the power system in the 0 Year System Outlook Report. NS Power is required to comply with the NPCC reliability criteria. These criteria are outlined in NPCC Regional Reliability Reference Directory # Design and Operation of the Bulk Power System and states that: The probability (or risk) of disconnecting firm load due to resource deficiencies shall be, on average, not more than once in ten years as determined by studies conducted for each Resource Planning and Planning Coordinator Area. Compliance with this criterion shall be evaluated probabilistically, such that the loss of load expectation [LOLE] of disconnecting firm load due to resource deficiencies shall be, on average, no more than 0. day per year. This evaluation shall make due allowance for demand uncertainty, scheduled outages and deratings, forced outages and deratings, assistance over interconnections with neighboring Planning Coordinator Areas, transmission transfer capabilities, and capacity and/or load relief from available operating procedures. DATE FILED: June 0, 0 Page of 0

41 0 0 0 As a part of the 0 IRP, NS Power completed a Loss of Load Expectation (LOLE) study which confirmed the results of previous studies calculating the required planning reserve margin to be 0 percent. The LOLE study confirmed that the 0 percent planning reserve margin applied by NS Power is required to meet the NPCC reliability criteria. As parts of NS Power s steam fleet continue to be transitioned from base loaded to increasingly peaking operation, NS Power expects there may be upward pressure on system forced outage rates associated with peaking units. Peaking operation of previously base loaded steam generating units, coupled with high levels of intermittent variable generation on the system, may drive the need to increase the planning reserve margin in order to maintain NPCC reliability criteria. The LOLE study will be updated in 0/0 as more operating data becomes available. The results of the Planning Reserve Margin LOLE study updates will continue to be reported in each annual 0-Year System Outlook Report... Analysis of Currently Planned Levels of Variable Generation Pursuant to the 0 IRP Final Report and Action Plan, NS Power committed to the following items: Continue to develop an understanding of the operational challenges associated with the planned increasing levels of variable generation integration and report to the UARB as part of the 0 Year System Outlook Report. Report to the UARB on the status of the need for flexible resources to integrate additional variable generation in the 0 Year System Outlook Report. During 0-00, conduct additional system studies to evaluate operations with increased levels of renewable resources that are expected over the next few years. DATE FILED: June 0, 0 Page 0 of 0

42 0 0 0 Include investigation of system requirements with fewer steam units providing real power operations. Report on the status of such efforts each year in the 0 Year System Outlook Report. Use Plexos to continue to assess hourly patterns of system need and resources with respect to operation under higher levels of wind resources expected over the next few years. During 0-0, continue to evaluate the coincidence of wind generation with peak load to better understand the capacity value of wind assets on the NS Power system. NS Power continues to evaluate the coincidence of wind generation with peak load to better understand the Effective Load Carrying Capability (ELCC) or capacity value of wind assets on the NS Power system. The capacity value of wind generation was determined to be percent of nameplate capacity for NRIS and 0 percent for ERIS connected generators for the planning purpose of the 0 IRP study. The overall ELCC of wind, including NRIS and ERIS resources, averages to percent. In the 0 Renewable Energy Integration Study, GE Energy used 00 AWS Truepower data based on locational wind speed measurements and weather forecasts to calculate ELCC of wind generation in 00 to be percent. NS Power is currently completing studies of variable generation using available data and both the LOLE and Cumulative Frequency Analysis methodologies. Although LOLE methodology is often used in the industry for the purpose of determining the ELCC of wind generation, it produces ELCC values with a significant annual variation. The DATE FILED: June 0, 0 Page of 0

43 0 0 International Energy Agency (IEA) Wind Task Final Report recommends that between 0 and 0 years of wind and load data is required to establish a reliable ELCC of wind generation. NS Power presently does not have the requisite amount of historical wind generation data in order to produce a reliable estimate of wind generation ELCC. The draft results of the comprehensive LOLE study reflect the shortcomings of the GE Energy calculated ELCC of wind, based on single year (00) wind speed measurements projected into the future. Until NS Power acquires operating experience with approximately 00 MW of wind generation and until sufficient data is available to reliably estimate the ELCC of wind generation in Nova Scotia there is risk to system reliability if the ELCC of wind generation is overstated. For the purpose of this report, NS Power continued to use a capacity value of wind consistent with the 0 IRP Assumptions of percent for NRIS and 0 percent for ERIS interconnected resources which average to percent overall ELCC of Nova Scotia wind generation resources. For planning purposes ERIS resources will be counted as not having a firm capacity component, as detailed in Section... Figure provides the preliminary results of a study of the years 00 0 wind and load data to determine the capacity value of currently planned wind using the LOLE methodology. The ELCC of wind generation based on this multiyear LOLE methodology appears to be between percent and percent, depending on the study year, at the presently contracted level of in-province wind generation of approximately 00 MW. As noted above, further wind generation data will need to be studied to produce a reliable estimate of wind generation ELCC. IEA Wind Task Final Report - DATE FILED: June 0, 0 Page of 0

44 Figure : ELCC of Wind Generation 0 NS Power s Cumulative Frequency Analysis assessment of the ELCC of wind generation provides a second method of quantifying the capacity value of wind on the NS Power system. The objective of the analysis is to determine what minimum capacity factor of wind we can predict to be available to the NS Power system, in peak hours, with required certainty. Cumulative Frequency Analysis is the technique of analyzing a set of historical data points, in this case hourly wind generation, to determine how often a particular value is exceeded. Other systems including CAISO (California Independent System Operator), BPA (Bonneville Power Administration), and SPP (South West Power Pool) use variations on this approach. NS Power s most recent analysis used hourly data for the period of 00-0 normalized to a capacity factor reflecting the installed wind at that time, filtered to include only the top 0 percent of peak demand periods. A continuous Beta probability distribution was fit to the data, and was then used to calculate the cumulative probability at various confidence levels. The results of DATE FILED: June 0, 0 Page of 0

45 0 0 Cumulative Frequency analysis, based on four years of actual wind generation data, are as follows: Confidence Level Capacity Value of Wind % % 0%* % % % 0% % * Fossil fuel steam generating plants usually have capacity value confidence level of over 0%. The 0 IRP Action Plan stated that NS Power would report on the status of the need for flexible resources to integrate additional variable generation onto the system. At this time, with the currently installed levels of wind, there appears to be no need for additional flexible resources on the system, other than Burnside # combustion turbine return to service, as included in the 0 GE Energy Renewable Energy Integration Study. NS Power will continue to monitor the system as the additional planned variable generation comes online and will report on the need for any flexible resources in future 0 Year System Outlook Reports. NS Power continues to evaluate operations with increased levels of renewable resources through ongoing system studies and analysis. NS Power is enhancing operational guidelines to deal with increased levels of wind generation, particularly during light load conditions. The wind fleet assessment shows that approximately 0 percent of wind generation on the system is not equipped with cold weather mitigation equipment. Without cold weather operation equipment, wind generators are prone to shutdowns due either to icing or ambient temperature during peak demand periods. Further, aspects of wind generation operation are being investigated to understand the potential reliability impacts of wind generation including effects on system inertia, frequency response, and voltage support. Until such studies have been completed and operational experience with DATE FILED: June 0, 0 Page of 0

46 0 0 0 a high level of wind generation has been gained, NS Power will continue to operate the system to mitigate reliability risks... Energy Resource Interconnection Service Connected Resources Pursuant to the 0 IRP Final Report and Action Plan, NS Power committed to the following item: ERIS connected wind resources will be evaluated for firm capacity contribution. During 0, NS Power will determine the extent to which ERIS resources can count as capacity towards resource adequacy during winter peak. ERIS interconnected generators are not counted towards available on peak capacity under the terms of the standard form GIA which states: Energy Resource Interconnection Service in and of itself does not convey transmission service. During the 0 Cost of Service Study and 0 IRP, some parties expressed the opinion that resources connected as ERIS could still provide on-peak capacity and that a portion or entirety of some ERIS resources should be counted as having on-peak capacity contribution, effectively reducing planning reserve margin requirement and the associated investment in firm capacity. As part of the IRP Action Plan, NS Power has reviewed GIP and available System Impact Studies for ERIS connected wind resources and maintains the position that ERIS connected resources cannot have firm capacity contribution. Independent Power Producers (IPPs) may request an ERIS to NRIS conversion by submitting a new Interconnection Request for NRIS service, and this initiates a SIS on behalf of the NSPSO. Should the SIS conclude that an ERIS installation meets the criteria required to be NRIS without additional system upgrades, such installations could become NRIS by amending the associated GIA. Should system upgrades be required, an ERIS installation will become NRIS following the completion of the required system upgrades and the amendment of the GIA. Reliance on ERIS connected resources as having some attributes of NRIS interconnected resources (i.e. firm capacity) without the DATE FILED: June 0, 0 Page of 0

47 0 0 requisite system studies, could lead to erosion of system reliability and, as such, is not recommended by NS Power... Energy Resource Interconnection Service to Network Resource Interconnection Service Conversion of Port Hawkesbury Biomass In 0, NS Power submitted an Interconnection Request to the NSPSO to convert the Port Hawkesbury Biomass generator from ERIS to NRIS. The subsequent SIS completed in May of 0 concluded that following the system upgrades which are scheduled to take place in advance of the Maritime Link coming online, no additional system upgrades are required in order to convert MW of net capacity of the Port Hawkesbury Biomass unit from ERIS to NRIS. As no additional system upgrades are required, a transmission Facilities Study will not have to be completed for this change to occur. The Port Hawkesbury Biomass Generator will change designation from ERIS to NRIS in accordance with the milestones of their revised GIA, following the transmission system upgrades (as noted in Section.) scheduled to take place in advance of the Maritime Link coming online. NS Power must complete operational testing of the Port Hawkesbury Biomass unit to validate the capacity performance of the facility. For the purpose of this report, MW of firm capacity has been assumed. The facility was not counted as firm capacity in the 0 IRP Assumptions.. Load and Resources Review The ten year load forecast and resources additions in Figure below are based on the capacity changes and DSM forecast in Figure. Figure provides details regarding NS Power s required minimum forecasted planning reserve margin equal to 0 percent of the firm peak load. DATE FILED: June 0, 0 Page of 0

48 Figure : NS Power 0 Year Load and Resources Outlook Load and Resources Outlook for NSPI - Winter 0/0 to 0/0 (All values in MW except as noted) 0/ 0 0/ 0 0/ 0 0/ 0 0/ 00 00/ 0 0/ 0 0/ 0 0/ 0 0/ 0 A Firm Peak Load Forecast,,,,,00,00,0,0,0,0 B DSM Firm 0 00 C Firm Peak Less DSM (A - B),,0,0,0,,,,,, D Required Reserve (C x 0%) 0 0 E Required Capacity (C + D),,,,,0,,,,,0 F Existing Resources Firm Resource Additions: G Thermal Additions H Hydro I Biomass 0 0 J Community Feed-in-Tariff K REA Wind Projects L Maritime Link Import Total Annual Firm Additions M (G + H + I + J + K + L) Total Cumulative Firm Additions N (M + N of the previous year) O Total Firm Capacity (F + N) + Surplus / - Deficit (O - E) 0 0 Reserve Margin % (O/C -) % % % 0% 0% % % % % % Thermal includes Burnside # (winter capacity 0 MW) which is assumed to be returned to service in 0/0. Also includes assumed unit retirement dates of as per the 0 IRP Assumptions. Hydro includes the assumption that the Harmony hydro facility will be refurbished. 0 Biomass shown includes a small IPP expected in-service within the 0 year period (0 MW) as well as MW from the PH Biomass plant which will be able to provide firm service following the transmission upgrades required for the Maritime Link, subject to operational validation. The Community Feed-in-Tariff represents distribution-connected renewable energy projects, outlined in the NS Renewable Electricity Plan in April 00. The Maritime Link Import and the forecast retirement of a solid fuel unit are assumed to coincide as outlined in the Maritime Link Application and the 0 Integrated Resource Plan. DATE FILED: June 0, 0 Page of 0

49 .0 TRANSMISSION PLANNING. System Description The existing transmission system has approximately,0 km of transmission lines at voltages at the kv, kv, 0 kv and kv levels. The configuration of the NS Power transmission system and major facilities is shown in Figure 0. Figure 0: NS Power Major Facilities in Service 0 0 The kv transmission system is approximately km in length and is comprised of km of steel tower lines and km of wood pole lines. DATE FILED: June 0, 0 Page of 0

50 0 0 0 The 0 kv transmission system is approximately km in length and is comprised of km of steel/laminated structures and km of wood pole lines. The kv transmission system is approximately km in length and is comprised of 0 km of steel structures and km of wood pole lines. The kv transmission system is approximately 0 km in length and is comprised of km of steel/concrete structures and km of wood pole lines. Nova Scotia is interconnected with the New Brunswick electric system through one kv and two kv lines providing up to 0 MW of transfer capability to New Brunswick and up to 00 MW of transfer capability from New Brunswick, depending on system conditions. As the New Brunswick system is interconnected with the province of Quebec and the state of Maine, Nova Scotia is integrated into the NPCC bulk power system.. Transmission Design Criteria NS Power, consistent with good utility practice, utilizes a set of deterministic criteria for its interconnected transmission system that combines protection performance specifications with system dynamics and steady state performance requirements. The approach used has involved the subdivision of the transmission system into various classifications each of which is governed by distinct design criteria (see Appendix B). In general, the criteria require the overall adequacy and security of the interconnected power system to be maintained following a fault on and disconnection of any single system component. The NS Power bulk transmission system is planned, designed and operated in accordance with North American Electric Reliability Corporation (NERC) Standards and NPCC DATE FILED: June 0, 0 Page of 0

51 0 0 criteria. NS Power is a member of the NPCC, hence, those portions of NS Power s bulk transmission network wherein single contingencies can potentially adversely affect the interconnected NPCC system are designed and operated in accordance with the NPCC Regional Reliability Directory Design and Operation of the Bulk Power System and are defined as Bulk Power System (BPS). On July, 0, the NERC Bulk Electricity System (BES) definition took effect in the United States. The BES definition encompasses any transmission system element at or above 00 kv with prescriptive Inclusions and Exclusions that further define BES. NS Power plans to adopt the NERC definition of the BES. In addition, NS Power has drafted an NS Exception Procedure for elements of the transmission system that are operated at 00 kv or higher for which contingency testing has demonstrated no significant adverse impacts outside of the local area. The proposed NS Exception Procedure would be used in conjunction with the NERC BES definition to determine the accepted NS BES elements and is equivalent to Appendix C of the NERC Rules of Procedure. The NS Exception Procedure was submitted for Board consideration on June, 0. The NPCC is conducting a consultation process on member exception procedures throughout 0. NS Power will be participating in this NPCC review involving other Eastern Canadian electric utilities, which is expected to conclude by the end of Q 0. As such, NS Power requested the Board hold the NS Exception Procedure in abeyance until the NPCC Consultation process is complete. In the event the NPCC process identifies issues which impact on the proposed NS Exception Procedure NS Power would revise and provide further submissions to the Board. NS Power makes use of Special Protection Systems (SPS) in conjunction with the Supervisory Control and Data Acquisition (SCADA) system to enhance the utilization of transmission assets. These systems act to maintain system stability and remove equipment overloads, post contingency, by rejecting generation and/or shedding load. DATE FILED: June 0, 0 Page 0 of 0

52 0 0 0 The NS Power system has several transmission corridors that are regularly operated at limits without incident due to these SPS.. Transmission Life Extension NS Power has in place a comprehensive maintenance program on the transmission system focused on maintaining reliability and extending the useful life of transmission assets. The program is centered on detailed transmission asset inspections and associated prioritization of asset replacement (for example, conductor, poles, cross-arms, guywires, and hardware replacement).. Transmission Project Approval The transmission plan presented in this document provides a summary of the planned reinforcement of the NS Power transmission system. The proposed investments are required to maintain system reliability and security and comply with System Design Criteria and other Standards. NS Power has sought to upgrade existing transmission lines and utilize existing plant capacity, system configurations, and existing rights-of-way and substation sites where economic. Major projects included in the plan have been included on the basis of a preliminary assessment of need. The projects will be subjected to further technical studies, internal approval at NS Power, and approval by the UARB. Projects listed in this plan may change because of final technical studies, changes in the load forecast, changes in customer requirements or other matters determined by NS Power, NPCC/NERC Reliability Standards, or the UARB. In 00, the Maine and Atlantic Technical Planning Committee (MATPC) was established to review intra-area plans for regional resource integration and transmission reliability. The MATPC forms the core resource for coordinating input to studies conducted by each member organization and presenting study results, such as evaluation DATE FILED: June 0, 0 Page of 0

53 0 0 of transmission congestion levels in regards to the total transfer capabilities on the utility interfaces. This information will be used as part of assessments of potential upgrades or expansions of the interties. The MATPC has transmission planning representation from NS Power, Maritime Electric Company Ltd., Emera Maine, Northern Maine Independent System Administrator, Newfoundland and Labrador Hydro, and New Brunswick Power (NB Power). NS Power and NB Power jointly conduct annual Area Transmission Reviews for NPCC.. Nova Scotia - New Brunswick Intertie Overview The power systems of Nova Scotia and New Brunswick are interconnected via three overhead transmission lines; one kv line from Onslow, Nova Scotia to Memramcook, New Brunswick, and two kv lines from Springhill, Nova Scotia to Memramcook, New Brunswick. The primary function of the intertie is to support system reliability. Access to the Nova Scotia - New Brunswick intertie is controlled by the terms of the respective OATTs of NS Power and NB Power. As previously mentioned in Figure there are currently seven active Transmission Service requests for Long-Term Firm Point-to-Point or Network Transmission Service. Power systems are designed to accommodate a single contingency loss (i.e. loss of any single element and certain multiple elements) and since the kv line carries the majority of the power flow (between NS and NB), loss of the kv line becomes the limiting factor. Power flow on the kv lines is also influenced by the loads in Prince Edward Island; Sackville, New Brunswick; as well as Amherst, Springhill and Debert, Nova Scotia. Wind generation in the Amherst area can also impact kv line loading. Note: there is only a single kv line from Springhill to Onslow. DATE FILED: June 0, 0 Page of 0

54 Import and export limits (both firm and non-firm) on the intertie have been established to allow the Nova Scotia and the New Brunswick system to withstand a single contingency loss. The limits are up to 0 MW export and up to 00 MW import. These figures represent limits under pre-defined system conditions, and differ for Firm versus Non- Firm Transmission Service. Conditions which determine the actual limit of the interconnection are shown in Figure. Figure : Conditions Determining Limits Export Import Amount of generation in Nova Scotia that can be rejected or run-back via SPS action Reactive Power Support level in the Metro Area Arming status of SPS Real time line ratings (climatological conditions in northern Nova Scotia) Net Northern Nova Scotia System load level Largest single load contingency in Nova Scotia Generation in the Amherst area Nova Scotia system load level (Import must be less than % of total system load) Percentage of dispatchable generation in Nova Scotia New Brunswick export level to Prince Edward Island and/or New England Seasonal line ratings (climatological conditions in northern Nova Scotia) Load level in Moncton area Largest generation/source contingency in Nova Scotia Generation in Amherst area Status of generation and transmission lines in New Brunswick Status of the intertie between New Brunswick and Quebec 0 If the kv Nova Scotia - New Brunswick intertie trips while exporting, the parallel kv lines can be severely overloaded and potentially trip, causing Nova Scotia to separate from New Brunswick. If this happens, the Nova Scotia system frequency DATE FILED: June 0, 0 Page of 0

55 0 0 (cycles/second) will rise, risking unstable generation plant operation and possible equipment damage. To address this, NS Power uses fast-acting Special Protection Systems to reject sufficient generation to prevent separation. If the NS Power system is separated during heavy import, Nova Scotia system frequency will drop. Depending on the system configuration at the time of separation and the magnitude of the import electricity flow that was interrupted, the system will respond and re-balance. The system does this by automatically rejecting firm and non-firm load through under-frequency load shedding (UFLS) protection systems as required. The degree of load shedding will be impacted by the amount of in-province generation supplied by wind power, due to the technical characteristics of that source. NPCC is currently conducting a study to assess the effectiveness of changes to the UFLS system changes adopted in 0. High penetration levels of wind generation in Nova Scotia reduce the total inertia of the NS Power system, thereby increasing the rate at which the Nova Scotia system frequency declines, resulting in the potential for higher levels of load shedding through UFLS. The loss of the kv line between Onslow, Nova Scotia and Memramcook, New Brunswick is not the only contingency that can result in Nova Scotia becoming separated from the New Brunswick Power system while importing power. All power imported to Nova Scotia flows through the Moncton/Salisbury area of New Brunswick. Since there is no generation in the Moncton/Salisbury area, and only a limited amount of generation in Prince Edward Island (PEI), power flowing into Nova Scotia is added and shares transmission capacity with the entire load of Moncton, Memramcook, and PEI. NB Power restricts power export to Nova Scotia to a level such that any single contingency does not cause adverse impacts on New Brunswick, PEI, or the intertie with New England. Any transmission reinforcement proposed to improve reliability, increase import and export power capacity or prevent the activation of UFLS in Nova Scotia must DATE FILED: June 0, 0 Page of 0

56 0 also consider the reinforcement of the southeast area of the New Brunswick transmission system. Although joint studies have been conducted, at this time the timing and configuration of an expansion to the provincial intertie has yet to be determined. However, given the dynamic nature of the provincial and regional electricity markets it is likely that an upgrade may be required over the next decade. Similarly, it is possible to identify the preferred route of the new line. To this end, NS Power continues to proceed with the acquisition of a right-of-way to accommodate a second kv circuit between Nova Scotia and New Brunswick. As of 0, percent of the required right-of-way has been acquired. P.0, M0, NS Power Capital Item 00, Right-of-Way Purchase, Northeastern Nova Scotia, approved by the UARB July, 00. DATE FILED: June 0, 0 Page of 0

57 TRANSMISSION DEVELOPMENT 0 TO 0. Transmission Development Plans Transmission development plans are summarized below. As highlighted earlier, these projects are subject to change. For 0, the majority of the projects listed are included in the 0 Annual Capital Expenditure Plan. For 0 onward, the projects are noted in the projected year of completion. 0 Study to assess the potential requirement for additional reactive power capacity in the Halifax Regional Municipality will be conducted. (CI Subsequent Submission in 0 ACE Plan) A study of the western valley sub-transmission system has identified combinations of load and generation that result in line overloads. A survey and analysis will be conducted to determine the feasibility of thermal upgrade of certain kv lines in the area. (CI 0 Subsequent Submission in 0 ACE Plan) Replacement of Lakeside / kv transformer with unit rated at 0/0/0 MVA. (CI Pending submission in 0.) In accordance with a directive from NPCC, Bulk Power System elements which previously fell within the grandfather clause of NPCC Directory 0, System Protection Criteria must have duplicate high-speed protection systems and duplicate station batteries. Onslow 0 kv will be uprated in 0. (CI Approved by the UARB on August, 0.) DATE FILED: June 0, 0 Page of 0

58 L-00 and L-00 Node swap at Onslow kv. This upgrade is associated with the Maritime Link project. (CI 0 No objection to proceed received from UARB on April, 0.) L- and L-0 thermal upgrade expected to be completed in 0. This upgrade is associated with Maritime Link project. (CI 0 Submitted to the UARB on April, 0.) The second kv line between Victoria Junction and Townsend Street will be reconductored. (CI 0 ACE Plan item approved by the UARB on May, 0.) A study will be conducted to evaluate the need to transfer load from the kv bus to the kv bus at Trenton, balancing load on the two kv kv autotransformers. A second kv - kv transformer is being installed at H Armdale to reduce the exposure to extended outages in the Peninsula core and to accommodate the load growth in the Spryfield area. New - kv distribution substation at Prime Brook, Sydney. Transformer, rated at MVA, will be tapped off transmission line L-. (CI 0 Subsequent Submission 0 ACE Plan formerly named George Street Substation.) Ground clearance issues with the 0 kv circuit L-00 between Port Hastings and Onslow will be addressed. DATE FILED: June 0, 0 Page of 0

59 Two capacitor banks totaling 00 MVar to be installed at kv in the Halifax area. (CI Subsequent Submission in 0 ACE Plan) L- transmission line re-build to increase the line rating. This upgrade is associated with the Maritime Link project. (CI Submitted to the UARB on January, 0.) Separating L-00 and L-00 at the Canso Causeway crossing to increase the Cape Breton export limit. This upgrade is associated with the Maritime Link project. (CI Subsequent Submission in 0 ACE Plan) In accordance with a directive from NPCC, Bulk Power System elements which previously fell within the grandfather clause of NPCC Directory 0 System Protection Criteria must have duplicate high-speed protection systems and duplicate station batteries. Port Hastings 0 kv will be uprated in 0. (CI 0 ACE Plan item approved by the UARB on May, 0.) Terminate transmission lines L-0 and L-0 at the 0S Woodbine substation. This upgrade is associated with the Maritime Link project and will be funded by NSP Maritime Link. A new kv transmission line will be constructed from the existing Dartmouth East substation to the new Harbour East substation. The Harbour East substation will be completed in 0. At Port Hastings, the kv bus, C-T, and C-T will be removed. Purchase and installation of a new - kv transformer at C Port Hastings. DATE FILED: June 0, 0 Page of 0

60 0 0 Retirement and removal of L-0 between Port Hastings and Cleveland. Woodbine substation expansion to accommodate new /0 kv transformer and breakers associated with transmission line terminals and HVDC converter station. This upgrade is associated with the Maritime Link project and will be funded by NSP Maritime Link. Ground clearance issues with the 0 kv circuit L-00 between Port Hastings and Onslow will be addressed. Upgrades beginning in 0 are expected to be completed by 0. (CI Subsequent Submission in 0 ACE Plan) Replacement of W-T transformer at Auburndale with a new /- kv transformer rated at /0/ MVA. 0 New kv substation at Harbour East, Dartmouth to be completed in 0. In accordance with a directive from NPCC, Bulk Power System elements which previously fell within the grandfather clause of NPCC Directory 0 System Protection Criteria must have duplicate high-speed protection systems and duplicate station batteries. Lingan 0 kv will be uprated in 0. Terrace Street kv substation will be retired once the existing kv distribution load is converted to kv (the latter is scheduled for 0). DATE FILED: June 0, 0 Page of 0

61 CONCLUSION Environmental legislation in Nova Scotia continues to drive a major transformation of the NS Power electric power system. The evolving design and operation of the NS Power system reflects this effort to comply with the NS Renewable Electricity Regulations, Air Quality Regulations and the Equivalency Agreement under the Canadian Environmental Protection Act. Within the 0 year window considered in this Outlook, NS Power will experience further reductions in hard caps for CO, SO, NOx and Hg, and will be required to serve 0 percent of sales with renewable electricity from qualifying sources. Compliance drives a shift towards renewable electricity generation and a reduction in conventional coal fired electricity production. This is evident in the introduction of new generating resources as outlined in Section and a forecast for coal and natural gas fired steam generator retirements as discussed in Section. Much of the new renewable electricity generation added to the system since 00 has been variable wind generation. While helping NS Power to meet legislated compliance levels, variable wind generation makes only marginal contributions to firm generating capacity. This presents challenges as NS Power forecasts low capacity factors on a portion of the steam generating fleet, which makes unit retirements appear economical. The exact timing of these retirements will be determined by the system conditions, such as: load forecasts and development of the Maritime Link. The 0 IRP study indicates that early steam fleet retirements are not optimal and neither is the addition of new intermittent renewable resources, absent any further legislated targets. The consistent theme across all studied plans in the 0 IRP is that extending the life of the steam generating fleet appears economic. NS Power will continue to monitor opportunities for increased levels of regional cooperation following the completion of the 0 regional dispatch pilot project with New Brunswick. DATE FILED: June 0, 0 Page 0 of 0

62 0 Year System Outlook Report Appendix A Page of Index of 0 IRP Action Items Addressed in the 0 0 Year System Outlook 0 IRP Action Item IRP Reference 0 Year System Outlook Reference Continue to develop an understanding of the operational challenges associated with the planned increasing levels of variable generation integration and report to the UARB as part of the 0 Year System Outlook Report. Report to the UARB on the status of the need for flexible resources to integrate additional variable generation in the 0 Year System Outlook Report. During 0 00, conduct additional system studies to evaluate operations with increased levels of renewable resources that are expected over the next few years. Include investigation of system requirements with fewer steam units providing real power operations. IRP Final Report, page, Section.. IRP Final Report, page, Section.. IRP Final Report, pages, Section.. Section.. Section.. Section.. Report on the status of such efforts each year in the 0 Year System Outlook Report. Use Plexos to continue to assess hourly patterns of system need and resources with respect to operation under higher levels of wind resources expected over the next few years. During 0 0, continue to evaluate the coincidence of wind generation with peak load to better understand the capacity value of wind assets on the NS Power system. Report on the ongoing evaluation of the planning reserve margin for the power system in the 0 Year System Outlook Report. ERIS connected wind resources will be evaluated for firm capacity contribution. During 0, NS Power will determine the extent to which ERIS resources can count as capacity towards resource adequacy during winter peak. Continue the thermal generation asset analysis work from the IRP process. By the end of June 0, file an initial thermal asset management plan striving to optimize the level of sustaining capital expenditures required for the fleet of coal/oil/gas plant. Update this plan each year in the 0 Year System Outlook Report. The plan will include the following: IRP Final Report, page, Section.. IRP Final Report, page, Section.. IRP Final Report, page, Section.. IRP Final Report, pages, Section.. Section.. Section.. Section.. Section. Recognition of uncertainty of many elements involved in this form of analysis. Recognition of/adherence to planning reserve margin requirement and level of planning reserve

63 0 Year System Outlook Report Appendix A Page of surplus associated with different net firm peak load trajectories based on then anticipated DSM peak reductions and associated net firm peak load forecast. Projections of possible retirement paths for the thermal fleet. Prioritization of units or plans for retention given system constraints. Consideration of locational value of Tufts Cove plant, and flexible operating characteristics of gas and oil fired steam units compared to coal fired units. There may be locational or system considerations that could give preference to sustaining capital or life extension expenditures at the Tufts Cove location compared to other plants. Consideration of location of other system resources, either NS Power owned or IPP owned, and their capacity value. Consideration of unit utilization forecasts and the significant driver that operating hours is for maintenance investment. Monitor ongoing developments of tidal energy and report to the UARB as part of the 0 Year System Outlook Report filed annually in June. File Renewable to Retail Tariff Application by September, 0. Complete the integration of the Maritime Link. Execute the Maritime Link transmission investments. Monitor cost effective market opportunities (imports and exports) as well as enhancements in regional balancing and interconnection and report on developments in the 0 Year System Outlook Report. IRP Final Report, page, Section.. IRP Final Report, page, Section.. IRP Final Report, page, Section.. IRP Final Report, page, Section.. IRP Final Report, page 0, Section.. Section.. Section.. Section. Section. Section..

64 0 Year System Outlook Report Appendix A Page of During 0, continue discussions with Newfoundland (NALCOR) and New Brunswick (New Brunswick Power) on greater regional electric system coordination: Provide an annual update to the UARB. Discuss need, impacts, and cost allocation associated with a second kv line to New Brunswick. Explore mechanisms to advance efficient regional unit commitment, dispatch, and operating reserve sharing policies. IRP Final Report, page 0, Section.. Section..

65 NS Power System Design Criteria 0 Year System Outlook Report Appendix B Page of ~ Nova Scotia,_. POWER An Emera Company NS Power System Design Criteria Report number NS Power-TPR-00-

66 0 Year System Outlook Report Appendix B Page of NS Power System Design Criteria REVISION RECORD Date Version Number /0/ 0 Approver, Date Signature I Comments Initial document 00/0/0 0/0/0 _!~-~eo P-..,_,_ I.. Updated to align with changes to System Design Criteria and better align with NERC/NPCC standards ~ g/d-iw\'{-o _ Revised fault clearing time ~~ I requirements for Primary and Secondary Transmission, contingency loading for Remote Transmission, and system transformer loading.!,

67 0 Year System Outlook Report Appendix B Page of NS Power System Design Criteria PURPOSE The purpose of this document is to state the Nova Scotia Power Inc. (NS Power) planning and development criteria to be applied to new additions to NS Power transmission system planned or constructed after the effective date ofthis document. NS Power's transmission system is divided into four classifications, each of which is governed by different design criteria. Where and when applicable, NS Power criteria will be superseded by the Northeast Power Coordinating Council (NPCC) criteria. The NS Power classifications are as follows:. Primary Transmission. Secondary Transmission. Electrically Remote Transmission. Transformation The NS Power System Design Criteria combine protection performance specifications with system dynamics and steady state performance requirements. When system expansions are undertaken, facilities are to be constructed such that the criteria are met. The specified speed of protection systems must be achieved unless faster speeds are specified or slower speeds are accepted based on system studies. System studies to determine adequacy and investment requirements must be conducted using the actual characteristics (setting and operating time) of existing protection systems. DEFINITIONS. Normal system conditions are defined to include all of the following: a. Expected load conditions. b. All transmission facilities in service (no line or transformer maintenance). c. Economically scheduled and dispatched generation allowing for planned generator maintenance outages (non-firm generation is not included as economically dispatched generation). Economic dispatch may be influenced by environmental or regulatory restrictions. d. Stable steady-state operation of the Interconnected Transmission System. e. All system voltages within % to 0% of nominal, unless otherwise noted. f. All system elements operating within their continuous thermal ratings, unless. otherwise noted. A system element is defined to be any one generator, transmission line, transformer or bus section.. Breaker back-up is defined to be protection against a local breaker's failure (mechanical or electrical) to trip when initiated by an associated protection operation. The term "Breaker failure protection" is used interchangeably in this document.. Single contingency is defined as loss of one system element with or without a fault. November 0 Page of

68 0 Year System Outlook Report Appendix B Page of NS Power System Design Criteria. PRIMARY TRANSMISSION SYSTEM Primary Transmission is defined as 0kV and above. The protection system must be designed with redundancy to cater to any single element failure, in keeping with good utility practice and conform to industry standards. Unless otherwise specified, and determined appropriate by transient stability studies, the following fault clearing times will be applied to the Primary Transmission system. Any deviations from these criteria must be submitted to the system planning group for approval. a. For a three phase or phase to ground fault on the local bus or on any element directly connected to the local bus such that it is within the instantaneous protection zone for that element (e.g. Zl,, 0) the fault contribution clearing time will be cycles. b. Where breaker failure protection is required to trip local breakers to isolate the fault described in item (a), the fault clearing time will be cycles. c. Where breaker failure protection is required to trip remote breakers to isolate the fault described in item (a), the fault contribution clearing time will be cycles. d. For a three phase or phase to ground fault on any element directly connected to the local bus such that it is outside the instantaneous protection zone for that element (e.g. Z, ) the fault contribution clearing time will be cycles. e. Where breaker failure protection is required to trip local breakers to isolate the fault described in item (d), the fault contribution clearing time will be cycles. f. Where breaker failure protection is required to trip remote breakers to isolate the fault described in item (d), the fault contribution clearing time will be cycles. Breaker failure protection will be applied to all Primary Transmission. The design criteria are:. From normal system conditions, the Interconnected Transmission System dynamic response shall be stable and positively-damped following a permanent three-phase fault on any one system element cleared in prime time. No cascade tripping shall occur.. From normal system conditions, the Interconnected Transmission System dynamic response shall be stable and positively-damped following a permanent line-to-ground fault on any one system element cleared in prime time. No cascade tripping shall occur.. From normal system conditions, the Interconnected Transmission System dynamic response shall be stable and positively-damped following a permanent line-to ground fault on any one system element cleared in breaker back-up time. No cascade tripping beyond elements cleared by the operative back-up protection shall occur.. From normal system conditions, following loss of any one system element with or without fault, all system elements shall be within 0% of their thermally limited ratings under the condition that the System Operator can take action within a 0 minute period to reduce load on the element. November 0 Page of

69 0 Year System Outlook Report Appendix B Page of NS Power System Design Criteria. From normal system conditions, for the loss of any one system element with or without fault, steady-state post-contingency Interconnected Transmission System bus voltages shall be not less than 0% or greater than 0% of nominal following correction by automatic tap-changers. In addition no bus shall experience a voltage change from prefault to post-fault condition greater than 0% before movement of tap-changers.. As far as possible, provision should be made to ensure that no fault is left permanently on the system.. SECONDARY TRANSMISSION SYSTEM This category includes all other loop transmission facilities, operating higher than 00 kv, which are not included in the Primary Transmission nor the Electrically Remote Transmission categories. The protection system must be designed with sufficient redundancy to cater to any single element failure, in keeping with good utility practice and conform to industry standards. The following fault clearing times will be applied to the Secondary Transmission system. Any deviations from these criteria must be submitted to the system planning group for approval. a. For a three phase or phase to ground fault on the local bus or on any element directly connected to the local bus such that it is within the instantaneous protection zone for that element (e.g. Zl,, 0) the fault contribution clearing time will be cycles. b. Where breaker failure protection is required to trip local breakers to isolate the fault described in item a), the fault contribution clearing time will be cycles. c. Where breaker failure protection is required to trip remote breakers to isolate the fault described in item a), the fault clearing time will be cycles. d. For a three phase or phase to ground fault on any element directly connected to the local bus such that it is outside the instantaneous protection zone for that element (e.g. Z, ) the fault contribution clearing time will be cycles. e. Where breaker failure protection is required to trip local breakers to isolate the fault described in item d), the fault contribution clearing time will be cycles. f. Where breaker failure protection is required to trip remote breakers to isolate the fault described in item d), the fault contribution clearing time will be cycles. Breaker failure protection will be applied to Secondary Transmission if system studies determine the requirement. The design criteria are:. From normal system conditions, the Interconnected Transmission System dynamic response shall be stable and positively-damped following a permanent three-phase fault on any one system element cleared in prime time. No cascade tripping shall occur.. From normal system conditions, the Interconnected Transmission System dynamic response shall be stable and positively-damped following a permanent line-to-ground fault on any one system element cleared in prime time. No cascade tripping shall occur. November 0 Page of